In seismic exploration, energy imparted into the earth by a seismic source reflects from subsurface geophysical features and is recorded by a multiplicity of receivers. This process is repeated numerous times, using source and receiver configurations which may either form a line (2-D acquisition) or cover an area (3-D acquisition). The data which results is processed to produce an image of the reflector using a procedure known as migration.
Seismic data migration typically uses diffraction traveltimes from subsurface imaging points to the source and receiver locations to produce an image of the subsurface reflectors. The diffraction traveltimes are the seismic signal propagation times along raypaths from each imaging point to the source and receiver locations. The propagation times, which are usually plotted as diffraction traveltime curves, are used after appropriate preprocessing of the raw seismic data to generate an estimate of the correct location of the reflector. The migration process will be familiar to those versed in the art.
Incorrect diffraction traveltime curves lead to at least two undesirable migration consequences. First, the image of the reflector which results will be poorly focused, making interpretation difficult. Second, the reflector may be mispositioned, a serious drawback in oil and gas exploration where accurate mapping of the subsurface structure is important. The effects of poor focusing and improper positioning are particularly apparent when migrating steeply dipping reflectors or when migrating in areas having significant lateral velocity variations.
In conventional practice, an estimated subsurface velocity model is used to generate the diffraction traveltime curves. One common method of estimating that model is to analyze seismic data corresponding to raypaths which are inclined less than about 45.degree. with respect to the vertical. The velocities can be determined by analyzing the variation in reflection traveltime as a function of distance between sources and receivers in the surface data. Because the near vertical raypaths are shorter than more nearly horizontal raypaths, the traveltimes are less sensitive to velocity errors and to lateral or vertical velocity variation. Unfortunately, accurate migration of steeply dipping reflectors, such as salt flanks and faults, also requires accurate traveltimes for raypaths that are closer to horizontal.
Another method that is used to obtain migration velocities is to prestack migrate several subsets of the surface seismic data. This is commonly done using either common-shot, common-offset or common-depth-point gathers. The migration is performed with an initial velocity model obtained from conventional normal moveout velocity analysis. If the migrations produce images that are consistent, the initial velocity model is taken to be correct. Otherwise, the velocity model is updated to give a model that gives a better migration. Several iterations are usually required to obtain a consistent migrated image. Variations of this method include depth focusing analysis and migration velocity sweeps.
Reflection tomography can also be used to determine migration velocities from surface seismic data. Reflection events on unstacked surface seismic data are first digitized. A gridded model of the subsurface is then optimized to give the best fit to the observed traveltimes. Unfortunately, surface seismic data do not contain enough information to uniquely specify both a migration velocity model and the reflector geometries. As a result, the derived velocity model may be ambiguous or geologically unreasonable. Improvements can be made by applying constraints to the optimization process, but those constraints generally reduce or eliminate the ambiguities at the expense of poorer fits to the traveltime data.
Vertical checkshot data and well sonic logs are also commonly used for obtaining a migration velocity model. Vertical checkshot data are gathered by placing a receiver in a well and measuring first arrival travel times from a source placed vertically above the receiver. These data are typically gathered at depth intervals in the well of 250 to 500 feet. Velocities can be determined from the checkshot data by dividing the distance between adjacent receivers by their associated traveltimes. Vertical checkshots therefore measure only the vertical velocity. Migrating the seismic data with the vertical checkshot velocity guarantees that reflections from nearly horizontal reflectors will be accurately imaged at the well. Unfortunately, a velocity that gives small traveltime errors for vertical raypaths may produce much larger errors for horizontal raypaths.
Sonic logs, like vertical checkshot surveys, measure vertical velocities. As a result, steeply dipping reflectors may be mispositioned. In addition, sonic logs suffer from the additional drawback that the velocity measurements are made at higher frequencies than are normally present in seismic data. Due to velocity dispersion (i.e. the variation of velocity with frequency), those frequencies are higher than are appropriate for migrating seismic data.
None of the above methods for determination of migration velocities account for velocity anisotropy (the variation of velocity with respect to the propagation angle of a raypath). Anisotropy is frequently present in seismic data as a higher order term in the diffraction event time-offset curves. Although a reasonably good match to observed seismic data can usually be obtained from an isotropic migration velocity model, for example the migrated images may be reasonably well-focused and consistent, the reflectors may nevertheless be mispositioned. Typically, any such mispositioning results from the fact that reflections from steep features have raypaths involving a large range of propagation angles, each of which may have velocities not taken into account by the isotropic model. In such cases additional information must be used to determine an anisotropic velocity model. This is generally a difficult task, given that even in laterally homogeneous media the higher order term may be hard to separate from terms associated with vertical inhomogeneities. In addition, conventional migration software does not usually account for anisotropy even if a reasonable anisotropic velocity model were available. As a result, conventional processing often suffers from an inability to accurately image steeply dipping reflections in regions having anisotropic media.
Migration velocities can also be estimated from vertical seismic profile (VSP) data gathered with sources at a range of offsets from the well. Optimization methods referred to as traveltime tomography are used to determine a velocity model. Unfortunately, the velocity model obtained from traveltime tomography suffers from the non-uniqueness problem similar to that which occurs in reflection tomography. In addition, the model produces a good migration at the well but degrades in image quality elsewhere. As in reflection tomography, imposition of constraints during the optimization reduces the ambiguities and produces geologically reasonable models at the expense of a poorer match to the traveltime data.
Migrated images may also be of poor quality as a result of the manner in which the traveltime curves are processed by the migration routines. Many migration programs, particularly those using the Kirchhoff method, sum the seismic data along traveltime curves corresponding to the first arrival only, and ignore subsequent arrivals. However, lateral velocity gradients and some geologic structures can lead to multivalued diffraction traveltimes, each of which may be important, or any one of which may be more important than the first arrival. In particular, later arrivals may carry more of the seismic energy than does the first arrival. If the migration ignores or mishandles the later arrivals, poor quality images will result.
Another constraint of some migration routines deals with the ability to migrate all points on the diffraction traveltime curve. Some routines are limited in the capacity to accurately migrate the entire curve. In such cases, it is preferable to migrate with traveltimes that are as accurate as possible for diffraction raypaths corresponding to the reflector dips of greatest interest. Those dips are often the steeply dipping reflectors, which are more sensitive to horizontal velocity errors than are horizontal reflectors. As noted, however, horizontal velocities are generally poorly characterized in conventional velocity models.
Once a diffraction traveltime curve has been derived and the seismic data has been migrated, it is useful for the data analyst to have an estimate of the accuracy of the position of the reflector in the migrated image. Conventionally, that estimate is obtained by correlating borehole measurements, such as from sonic logs or dipmeters, with the image. High correlations indicate an accurate migration.
There are several limitations to the correlation approach however. A poor correlation with borehole data may indicate migration error, but does not quantify that error. In addition, other problems, such as inaccurate estimation of the seismic wavelet, can lead to poor correlation between well data and a seismic image. And finally, a good correlation between well data and the shallow dipping reflectors in the image does not necessarily imply that the steep dips are accurately migrated. In particular, because wells do not always penetrate steeply dipping reflectors, such as the flanks of salt domes, the correlations are not meaningful at the locations in which the greatest accuracy is desired. Because hydrocarbon reserve estimates can be quite sensitive to the position of the steeply dipping reflectors, the correlations are often of limited value to the analyst.
Fundamental to this entire discussion of conventional practice relating to the development of diffraction traveltimes is the reliance on the velocity model as the desired or preferred input to the migration process. However, velocities are neither the fundamental parameters required for migration, nor the parameters directly obtained from field measurements. Rather, traveltimes are the underlying parameters on which migration accuracy relies, and the traveltimes associated with the raypaths for a family of source and receiver configurations are the parameters directly obtained in the field. Procedures which rely more directly on traveltimes as a migration input would reduce errors deriving from the use of velocity models, and are therefore desired within industry.
From the foregoing, it can be seen that there is a need for a method of generating diffraction traveltimes for use in seismic migration which gives improved accuracy for near-horizontal raypaths, which can handle velocity anisotropy, and which takes into account multivalued traveltime curves. Preferably, the method should rely on measured diffraction raypath traveltimes to provide for accurate migration of seismic data, either directly as an input to migration or indirectly by improving the accuracy of the input velocity model. The method should also provide for a quantitative estimate of any migration error. The present invention satisfies these needs.